1. Technical Field
Embodiments described herein relate to systems and methods for subsurface wellbore completion and subsurface reservoir technology. More particularly, embodiments described herein relate to systems and methods for assessing diverter effectiveness in fracture wellbores in subsurface hydrocarbon-bearing formations.
2. Description of Related Art
Ultra-tight hydrocarbon-bearing formations (e.g., hydrocarbon-bearing resources) may have very low permeability compared to conventional resources. For example, the Bakken formation may be an ultra-tight hydrocarbon-bearing formation. These ultra-tight hydrocarbon-bearing formations are often stimulated using hydraulic fracturing techniques to enhance oil production. Long (or ultra-long) horizontal wells may be used to enhance production from these resources and provide production suitable for commercial production. However, even with these technological enhancements, these resources can be economically marginal and often only recover 5-15% of the original oil-in-place under primary depletion. Therefore, optimizing the development of this resource and the technology applied to this resource is critical.
Diverters are used to divert the flow of well treatment fluids (e.g., injection fluids) fromperforations taking more fluid to perforations taking less fluid. Diverters may be used to temporarily block off runaway fractures or low stress zones in a stage, which more readily propagate hydraulic fractures, forcing fracturing fluid and sand into new fractures. There are many types of commercial diverters including diverters that block perforations in the wellbore itself (sometimes known as wellbore diversion or near wellbore diversion) and diverters that pass through the well into the fractures where they block propagation in the hydraulic fractures themselves (sometimes known as deep diversion). Diverters, however, may be unreliable due to uncertainty in whether a diverter is going to work or not. For example, many fractures may be open in the wellbore and this can result in a great deal of uncertainty in where the diverter is going and what effect the diverter is going to have in the wellbore to mitigate the growth of the largest fracture, in some cases.
FIG. 1 depicts an example plot of diverter effectiveness for a series of diverter drops. As shown in FIG. 1, diverters only work a fraction of the time (e.g., impedes or stops by the diverter). More than half the time, diverters may accelerate the growth of the largest fracture or has no impact on the largest fracture. Thus, being able to identify if a diverter works to stop or impede growth of the largest fracture is important due to the less 50% chance the diverter will work.
One method that has been used to attempt to assess the effectiveness of diverters is a Delta P measurement. FIG. 2 depicts an example of a plot of Delta P versus diverter event counts. As shown in FIG. 2, there does not appear to be any correlation between Delta P and the effectiveness of the diverter on the growth of the largest fracture (either stops, impedes, no impact, or accelerates). Thus, there is a need to be able to affectively assess if the diverter is effectively plugging existing perforations. More effective assessment of the diverter may be used to improve the use of diverters.